When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. For the purposes of the present disclosure, such a fluid will be referred to as a “well fluid.” Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling into a targeted formation), transportation of cuttings to the surface, controlling formation pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which a well is being drilled, fracturing the formation in the vicinity of a well, displacing the fluid within a well with another fluid, cleaning a well, testing a well, emplacing spacer or fluid loss control pills at various points in the displacement, completion, or work-over process, emplacing a packer fluid in the completed wellbore during production, preparing the well for abandonment, abandoning the well or, otherwise treating the well or the formation. A commonly used type of well fluid is based on water-based solutions including brines. Brines, such as CaBr2 brine, are commonly used as well fluids because of the ability to control the density of the solution over a wide density range. Further the brines are typically substantially free of suspended solids and brines typically do not damage the more common types of subterranean formations.
When drilling progresses to the level of penetrating a hydrocarbon-bearing formation, special care may be required to maintain the stability of the wellbore. Examples of formations in which problems often arise are highly permeable and/or poorly consolidated formation and thus a technique known as “under-reaming” may be employed. In conducting the under-reaming process, the wellbore is drilled to penetrate the hydrocarbon-bearing zone using conventional techniques. A casing generally is set in the wellbore to a point just above the hydrocarbon-bearing zone. The hydrocarbon-bearing zone then may be re-drilled to a wider diameter, for example, using an expandable under-reamer that increases the diameter of the wellbore. Under-reaming usually is performed using special “clean” drilling fluids. Typically the “clean” drilling fluids used in under-reaming are aqueous, dense brines that are viscosified with a gelling and/or cross-linked polymer to aid in the removal of formation cuttings. The expense of such fluids limits their general use in the drilling process.
When the target subterranean formation has a high permeability a significant quantity of the drilling fluid may be lost into the formation. Once the drilling fluid is lost into the formation, it becomes difficult to remove. Removal of the aqueous based well fluids is desired to maximize the production of the hydrocarbon in the formation. It is well known in the art that calcium- and zinc-bromide brines can form highly stable, acid insoluble compounds when reacted with the formation rock itself or with substances contained within the formation. These reactions often may substantially reduce the permeability of the formation to any subsequent out-flow of the desired hydrocarbons. As should be well known in the art, it is widely and generally accepted that the most effective way to prevent such damage to the formation is to limit fluid loss into the formation. Thus, providing effective fluid loss control is highly desirable to prevent damaging the hydrocarbon-bearing formation. For example such damage may occur during, completion, drilling, drill-in, displacement, hydraulic fracturing, work-over, packer fluid emplacement or maintenance, well treating, or testing operations.
Techniques that have been developed to control fluid loss include the use of fluid loss control “pills.” As the term is used in this disclosure a “pill” is a quantity of fluid added to the well fluid so as to temporarily change the properties of the well bore fluid at or near a specific point in the well bore. Significant research has been directed to determining suitable materials for the fluid loss pills, as well as controlling and improving the properties of the fluid loss pills. Typically, fluid loss pills work by enhancing filter-cake buildup on the face of the formation to inhibit fluid flow into the formation from the wellbore; however the fluids in accordance with the claimed subject matter are effective by developing extremely high viscosity in the environment at and just within the face of the formation to inhibit fluid flow into the formation from the wellbore. Because of the high temperatures, high shear (caused by the pumping and placement of the pill), high pressures, and low pH to which well fluids may be exposed (i.e., “stress conditions”), synthetic polymeric materials typically used to form fluid loss pills and to viscosify the well fluids tend to degrade rather quickly.
One class of viscosifiers commonly used in the petroleum industry comprises polymeric structures starting with molecular weights of hundreds of thousands to several million grams per mole. These large, chemically bonded structures are often crosslinked to further increase molecular weight and effective viscosity per gram of polymer added to the fluid. These large molecules are quite stable under the thermal conditions typically encountered in a subterranean reservoir. However, this thermal stability is believed to contribute to decreased well productivity. As a result, expensive and often corrosive breakers have been designed to destroy the molecular backbone of these polymeric structures. These breakers are typically oxidizers or enzymes and are at best only partially effective with typical reservoir cleanup less than 80% complete and more usually much less than 50% complete. It is also reported in the literature that the long term stability of polymeric based thickening agents is shortened by the high temperature, high shear, high pressures, and low pH to which well fluids may be exposed (i.e., “stress conditions”).
Viscoelastic surfactants are commonly used in the petroleum industry as an alternative to the above mentioned polymeric thickening agents. Viscoelastic surfactants are relatively small molecules with each molecule being typically less than 500 grams per mole (i.e., molecular weight less than 500). These small molecules will associate under certain conditions to form structures which resemble the polymer molecules but which are not stable structures. The individual molecules of surfactant begin to associate to form rod-like or spiraling-cylinder-like micelles. These micelle structures are always in an equilibrium state of breaking and reforming. As dynamic structures, these polymer-shaped micelles are readily destroyed by shear, presence of hydrocarbons or increased temperature. While these features are desirable especially in a hydrocarbon-bearing formation, there is minimal control over the conditions under which micelle breakup occurs. Therefore, under conditions of exposure to oil, high temperature, high shear, or other “stress conditions”, the viscoelastic surfactants rapidly return to their original small independent spherical micellar state. When the viscoelastic micelles are broken down to this small independent spherical micellar state, the desired viscous nature of the well fluid is lost. In some cases the loss is temporary, in others the loss may be more permanent.
Presently there exists an unmet need for a simple, inexpensive way to increase the thermal range for viscoelastic-surfactant-based viscosifying agents used in downhole applications. Preferably, this thermal extender would be applicable to various viscoelastic-surfactant-based viscosifying agents.